Power marketing is a function which is novel for the electric industry.
However, it is by no means a novel function. In every commodity market, marketing is used
to meet customers demands. While the Federal Energy Regulatory Commission
("FERC") certifies "power marketers," this is merely a regulatory
definition, and not a commercial one. Traditional utilities, as well as the new nonutility
marketers will necessarily engage in marketing in the service of their customers. Power
marketing is price creation through the use of price risk management tools. The purpose of
this monograph is to provide an introduction to those price risk management tools, known
as "derivative" products, and their application.

Background

Almost since its inception, electric service has been treated as a
monopoly. This meant that the entities which sell electricity have been required to do so
on a cost of service basis. Rates were regulated, and based upon cost of
production. There was no price differentiation.

This began to change with the implementation of PURPA, as for the first
time, certain qualifying power companies could sell their output without having their
costs subjected to regulatory scrutiny. A "rate" was set, based upon the purchasing
utilitys avoidedcosts, and the qualifying power company would garner
profits (or losses) based on how well it could control its own costs.

While this was in itself revolutionary, it was well short of true price
creation. However, it did start the process moving. By the latter part of the 80s,
the concept of avoided costs had been largely displaced by competitive procurements
run by utilities seeking low-cost power supplies. The purchasers costs were to be
measured by the market alternatives. With this step, a crude market was created.

However, this nascent market was still constrained by the limited
ability of purchasing utilities to seek suppliers beyond their immediate neighbors. There
were only limited rights to transmit power over those neighbors lines.

By the early 90s, it had become clear that the industry and the
nation would benefit if low-cost electricity could flow more easily. Congress responded by
passing the Energy Policy Act of 1992 (EPAct).

EPAct granted the FERC the authority to require utilities under its
jurisdiction to transmit power. Over a period of years, FERC issued a series of orders and
policy statements implementing EPAct.

This process culminated with FERCs Order 888 which finally
required utilities to file "pro forma" transmission tariffsstandard
transmission contracts available to anyone in the wholesale market.

With FERC Order 888 in place, a true wholesale market has developed.
Power is now regularly traded over distances not previously feasible, increasing the
efficiency of the electric industry by permitting higher-cost generation to be displaced
by lower-cost resources. Markets have expanded and become more efficient.

But this physical change was just the beginning. The ability to move
electricity provides physical liquidity. The next step, quickly recognized, was to create price
transparencythe ability to quickly and accurately determine the price of
electricity.

In a regulated industry, there are no prices, just cost-based tariffs.
As we continue to shift to a market model in the electric power industry, prices become
all-important. It is the means by which consumers select their suppliers.

The first steps in achieving price transparency are taking place

The New York Mercantile Exchange began trading monthly electricity
futures contracts in April of 1996. Thus far there are only two contracts trading, both in
the Western U.S. However, NYMEX intends to launch at least one contract in the Eastern
U.S. in the summer of 1997.

Both Dow Jones and McGraw-Hill have introduced a series of
electricity price indices, quoting daily and weekly prices in a number of trading
locations.

Electricity brokers are offering an increasing array of price quotes
for a variety of terms and locations.

Electricity is now well on its way to becoming commoditized in the
wholesale market.

This price transparency in the wholesale market has been noted at the
state level, where utilities, commissions and legislators are increasingly looking to
follow FERCs lead, encouraging competition at the retail level.

California, New Hampshire, Rhode Island, and Pennsylvania have passed
laws permitting customers to choose alternative power suppliers. Utilities in Illinois,
New York, Massachusetts, New Hampshire, Washington and Idaho have implemented pilot
programs and are currently allowing retail customers to select the suppliers of their
choice.

When given that choice, customers select their suppliers,
overwhelmingly, based upon one thingprice. However, prices dont appear out of
nowhere. They are created. Price creation is the key element of power marketing. The
implications of this for the electric power industry are dramatic. As electric power
becomes deregulated, it will begin to act more and more like other energy commodities.

Marketing of energy commodities is engaged in by energy producers in
other industries, and traditional power generation companies will employ the tools of
marketing also. However, they will be joined by other commodities tradersoil and
natural gas trading companies, Wall Street trading firms and commodity investment houses.
In the commoditized energy markets, most transactions are not between producer and
consumer, but among marketers, continuously building and adjusting their portfolios
in order to deliver a competitive price to their customers.

Electricity is merely the last of the great regulated industries to be
subjected to deregulation and commoditization. As this process continues, we are already
seeing the new products which will change the nature of the industry.

These products are what are known as derivative products.
Derivative products are the bulwark of a global price risk management system. The
following pages explain how derivatives can be used in energy commodity transactions.

Power Marketing:
Price Creation in a Commoditized Electric Power Market

The prices in the cash trading market and the physical commodity market
converge over time. During this time derivatives can be used to manage the risk of price
volatility. The basic derivative products are:

Forward Contracts

Futures Contracts

Basis Contracts

Options, and

Swaps.

Forward Contracts. A forward contract is an agreement for the
delivery of a commodity in the future, generally for a term which may be from a month to
years long, at prices fixed at the inception of the agreement. Forwards do not trade on
exchanges and therefore offer more flexibility to contracting parties but more risk than
exchange traded derivative instruments.

While the electric power industry has long had multiyear agreements,
these have been primarily cost-based agreements, in which the price was not fixed, but
rather fluctuated with the suppliers cost of production. Because prices were not
fixed at the inception of the agreement, these multiyear contracts cannot be considered
forward contracts.

Forward contracts have been uncommon outside the realm of
PURPA-mandated, long-term contracts based upon projected avoided costs. To the extent that
these contracts were the product of regulatory mandate, they are poor examples of true,
market-oriented forward contracts.

Nevertheless, the forward contract is the bulwark of the
marketers business. When a customer needs power supplies, it goes out for bid. The
key component of a winning bid is a fixed price for the term sought. It is impossible to
win or hold customers in a competitive market without the capability to offer forward
contracts.

Fixed price forward contracts will need to be created, in volume, on
demand, and in a fashion which permits the supplier to "lock in" a certain
price.

In their crudest incarnation, forward contracts may be offered directly
by a marketer which simply relies upon its own views of the future, as reflected in its
internal "forward curve," and which is willing to bet that the price it offers
in the forward contract will be above its cost of production or acquisition. However, this
is a risky way to do business. The market is punishing toward a marketer which offers
"unhedged" forward contracts. If it turns out the costs are
higher-than-expected, the marketer can lose tremendous amounts of money quickly.

For example, if a marketer were to agree to deliver 200,000 mWh over a
one year period at a fixed price of $20/mWh, and the actual cost of obtaining and
delivering power was $30/mWh, the marketer could lose $2 million on that single
transaction.

In order to protect against these losses, in the absence of hedging
mechanisms, the marketer will only offer to sell forward contracts at relatively high
prices, and to buy under forward contracts at relatively low prices, creating a large
"spread" between purchase and sale prices. The larger the spread, the less
efficient the market, and the more customers must pay for a priced product.

To improve market efficiency, marketers have supported the New York
Mercantile Exchange (NYMEX) in its efforts to establish electricity futures contracts.
Two of these are already trading.

Electricity Futures. A futures contract is a standardized contract,
traded on an exchange, and subject to regulation by the Commodities Futures Trading
Commission (CFTC). Futures standardization provides more financial liquidity than
other devices in the world of commodities.

There are currently two NYMEX electricity futures contracts. The
difference between the two contracts are their delivery locations. One contract is for
delivery at the California-Oregon Border, which is referred to as "COB," and the
other is the Palo Verde substation in Arizona. Otherwise, the terms and conditions of the
contracts do not differ.

The electricity futures contracts require the seller of a contract to
commit to deliver 736mWh each month at the contract price agreed to. The contracts are for
firm energy. This number comes from the requirement that electricity be delivered in
increments of 2 mW per hour, for 16 hours each business day, beginning at 6 a.m. and
ending at 10 p.m., 23 business days each month (there are provisions for delivery on
certain Saturdays during short months). 2 x 16 x 23=736. This obligation to deliver is
backed by the exchange (NYMEX).

Futures contracts cannot be negotiated, except for price, which
once set, is locked in for the month covered by the contract. The fact that the contracts
are standard is what makes them liquid, and therefore valuable for power marketing
purposes.

Contracts are traded out eighteen months, which makes them more than
adequate for the creation of the most popular futures contract, the fixed price, one year
contract.

To understand the importance of the futures contract to marketers,
compare the situation of a marketer facing a California customer in 1998 with and without
the NYMEX futures contract.

Without the futures contract, the marketer must guess what the cost of
electricity will be during 1998, then build in a hedge to protect against errors.

With futures contracts, marketer risk can be substantially controlled,
by purchasing a "strip" of futures contractsthat is, one futures contract
for each month of the year-long customer forward contract. When the customer asks for a
price quote, the marketer simply checks to see the current offered price for futures
contracts for the twelve months, calculates a weighted average, and makes an offer to the
customer. If the customer accepts, the marketer purchases the strip, and to a great
extent, locks in its profits. The guesswork of creating a forward price offer is largely
eliminated, dramatically reducing the spreads required by the marketer, and thus reducing
the price paid by the customer.

Creating a forward price offer using futures contracts

In this example, the customer may be offered a price of just above
$19/mWh for peak hours. How far above depends upon the marketers overhead and profit
requirements for the transaction.

It is important to note that while the purchaser of a futures contract
can take delivery of its electricity at the trading hub, almost none do so. Over 95% of
these contracts are "closed out" before it is time for them to go to
"delivery." This is accomplished by simply selling one futures contract for
every contract purchased.

Why do this? Because the primary purpose for futures contracts is to
act as a financial hedge, not as a source of electricity. In the example above, a marketer
purchases a futures contract for August delivery at $23/mWh. The summer turns into a hot
one, and electricity prices soar to $33/mWh by the end of July. The purchaser simply sells
the contract for $33/mWh, taking a $7,360 profit (736 MWHs per contract x $10 per MWH
profit). This profit is then used to offset the cost of purchasing physical power in
August.

The purchaser could take delivery at the California-Oregon Border, and
transport the power to where it is needed, say in Southern California. However, there may
be local powerplants which can sell electricity for less than the COB price-plus
transportation costs. It is therefore generally more efficient to rely on the futures
market for the financial hedge, while obtaining physical electricity supplies elsewhere.

The exchange-traded futures contracts are extremely important for
marketers, and will be traded in massive volumes as customers are offered fixed price
forward contracts. To understand just how large this business will become, it is useful to
compare the natural gas industry to the natural gas futures contract. The U.S. uses $60
billion in natural gas (retail) each year. To provide fixed prices just to that segment of
the market which can access them, and which are not still exclusively served by local
distribution companies, gas marketers purchase $300 billion worth of natural gas futures
each year. The dollar volume of the natural gas futures contract exceeds the actual
physical volume consumed by 500%, and the natural gas market is only about 50%
deregulated!

If electricity follows the same pattern, as is likely, we can expect
the $200 billion electricity industry to be supported by a trillion dollars in futures
contracttrading within the next five years, as retail markets open and
customers demand price quotes.

To help this occur, NYMEX is planning additional futures contracts. It
is anticipated that by the summer of 1997, NYMEX will launch at least one more electricity
futures contract in the eastern interconnection, to supplement the two currently traded in
the western interconnection. This is necessary, because the eastern and western
interconnections can physically tolerate little trade between them, and prices between the
two interconnections therefore have little in common.

In fact, this problem of requiring separate trading hubs in the east
and west mirrors a similar problem within each synchronous region. There are lesser, but
still serious, transmission constraints within regions which make it likely that prices in
one subregion will differ from those in other subregions.

Theoretically, NYMEX could create dozens of futures contracts. However,
it must balance the need for comprehensive coverage against the loss of liquidity which
would result from a proliferation of futures contracts. If there are too many futures
contracts, it becomes less likely that a marketer will be able to buy and sell any
particular contract on demand. Thus, NYMEX must limit the number of trading hubs for which
it provides futures contracts, and leave the remaining risks to off-exchange
mechanismsthe so-called "over-the-counter" products. Of primary importance
among these over-the-counter products is the "basis contract."

Basis Contracts. Basis contracts reflect, and are designed to
permit marketers to hedge against fluctuations in the difference in prices between two
location points. Typically, one point is a NYMEX futures contract trading point, such as
COB, with the other point being a heavily-traded subregion, for example, Sacramento.

When a customer in Sacramento requests a price quote for a one-year
forward contract, the marketer can readily calculate a strip of NYMEX contracts traded at
COB, and make a price offer. Most of the risk in making that offer can be eliminated, by
simply "buying the strip." However, the marketer still has to deliver power to
the customer.

One way of doing this would be to simply purchase firm transmission
from the California-Oregon Border (COB) to Sacramento for the year term. The marketer can
look up the tariff, add in the firm transportation price to its bid, and be done. However,
such a marketer will regularly be undercut by other, more competent marketers.

This is because it may be possible to purchase power locally, and avoid
transportation costs. This may be done all year long, or just part of the year. It might
be done on a full requirements contract, or as a standby contract so that the marketer can
use interruptible transmission. There are numerous approaches which may be used to assure
that the Sacramento customer gets its power supply without the need to physically
transport power from COB. But most marketers will never deal with this. Rather, they will
rely on market makers in basismarketers which specialize in "basis
contracts," who will guarantee a price differential between the NYMEX contract and a
subregional trading point such as Sacramento.

There are even circumstances in which a basis contract can be a
negative number. Thus, for example, because electricity can be less expensive in Alberta
than at the California-Oregon Border, it is not unusual for a basis quote to be "COB
minus" for power delivered to Alberta.

Basis contracts are generally less expensive than purchasing year-round
firm transportation, which is why a marketer must use them in order to survive in a
competitive environment.

The marketer which specializes in basis contracts for a given region
makes its money by estimating correctly the price difference between one point and
another. It studies transportation tariffs, but also nonfirm transmission rates, numbers
of interruptions of nonfirm transmission service on various routes, and the cost of
purchasing electricity at secondary trading points. This type of calculation is
qualitatively the same as that made by the marketer offering forward contracts in the
absence of the NYMEX futures contracts. However, because the NYMEX contract eliminates the
greatest share of the risk, basis risk is quantitatively much smaller.

In sum, basis contracts permit the marketer to lock in differences
in prices between two points, typically a NYMEX trading hub and a secondary trading
point. Just as NYMEX prices fluctuate continuously, so, to a lesser extent, do basis
quotes. Also, just like NYMEX prices, basis prices will differ month-to-month (although
generally price quotes for basis contracts will be the same for months during the same
season). In the example here, basis prices have been added to a "strip" to bring
the marketer closer to the final price quote to be given the customer.

Options Contracts. Now the marketer has in place a NYMEX strip, and
a basis contract. He can make an offer to the customer of a fixed price contract for the
year, and rest easy, knowing that if accepted, he has locked in his profit. But has he?
Customers, particularly smaller customers, demand "full requirements contracts."
These are contracts in which the customer pays the same price per kWh, no matter how many
kWhs they use. Experience has shown that customers are willing to accept the idea that if
they buy more electricity, they have to pay morebut customers dont want to be
told that their price will change. After all, they selected their supplier based upon
price.

In the example above, the customer has a flat load factori.e.,
it uses the same amount of electricity in each month. This is not often the case, but
different load factors do not present a difficult problem for the marketer. A typical
customer will use more electricity in the summer than in the spring or fall. To
compensate, the marketer may buy two futures contracts for July and August, when the air
conditioning is on, for every one futures contract it buys for April and May, when the
windows are open. Then the "strip" becomes a weighted average of the contracts
required to be purchased for the customer. A customer which uses a great deal of
electricity during summer peaks will pay more per kWh than a customer which uses
electricity in constant quantities.

However, this leaves the supplier with another problem. It has made an
offer based upon the customers projected pattern of use, often based upon historical
averages. But what if it is an exceptionally hot summer? Or, just as problematic, what if
it is an exceptionally cool summer? In the first case, the marketer wont have locked
in the price on sufficient power supplies, and may have to buy on the open market at high
prices. In the second case, the marketer may have too much power supply locked in, and it
may have to sell in a depressed market. A marketer, operating on thin margins, can afford
neither.

To protect against these possibilities, the marketer may use options
contracts. These come in two basic types: calls and puts.

Call Options

The purchase of a call option gives the buyer the right, but not the
obligation, to purchase the commodity at a set price. One can purchase a call option on an
electricity futures contract. If, for example, electricity contracts are trading at
$20/mWh for July, one might purchase the right to buy that contract for perhaps $1/mWh.
This would effectively "cap" the price of additional July power at $21/mWh (the
option price plus the exercise price). However, should July be a normal month, and the
marketer didnt need the power, it would be under no obligation to take it. The
marketer would simply choose not to exercise its "call option."Thus, call
options permit the marketer to offer a "full requirements contract," at a fixed
price, with minimal risk that the marketer will lose money by having to purchase
high-priced power in a hot summer.

Put Options

Similarly, there is a risk that July will be unusually cool. In such
cases, customers will not use as much electricity as was projected, and electricity prices
are likely to fall. The marketer would have to sell its surplus electricity at a loss,
unless it has "put options."

A put option gives the holder the right, but not the obligation, to
sell electricity at a predetermined price.

To extend our example, the marketer might purchase a put option with a
strike price of $20/mWh, for a cost of $1/mWh. If prices fall, the marketer can exercise
its put option, and sell the electricity for $20.

If a marketer uses options, it is only likely to use them during
periods when unusual weather would have a severe impact  i.e., during summer and
winter peak periods. The cost of the call and put options can be included in the price bid
to the customer.

The marketer now has a basis for making a price offer to the customer.
It will be $21.66 plus an amount designed to cover the marketers overhead, profit
and risks, including accounts receivable risk, and residual price risk.

Puts and calls on electricity futures contracts are themselves traded
on the NYMEX. However, options may be purchased on other products, such as basis
contracts, also. These are not exchange traded, and therefore are referred to as
"over-the-counter options." Also, some marketers wont bother with options,
but will rather take the risk themselves, effectively managing this residual risk
internally.

Options are powerful tools, and may be used for a variety for hedging
and speculative purposes by more sophisticated marketers.

For example, a power producer might purchase a "put" in order
to place a floor under its revenues. By purchasing a put with a "strike
price" of $20/mWh, a power producer guarantees that it will receive at least $20/mWh.
If market prices are higher, the power producer simply chooses not to exercise the put,
and sells at market rates. If market rates are lower, the producer exercises the put, and
sells at the $20 floor price.

A power producer could also obtain additional income by selling a
"call." By selling another company the right, but not the obligation, to buy
power at $25/mWh, the power producer earns premiumsthe amount paid by the
buyer of the call option. However, the price it pays is that if market prices go above
$25/mWh, the purchaser of the call will surely exercise it, and force the producer to sell
at a ceiling price of $25/mWh.

The power producer can even combine the two. By simultaneously
purchasing a put and selling a call, a power producer can create what is known as a
"no-cost collar," in which the price of electricity can go no lower than the
floor created by the put, and no higher than the ceiling created by the call. The premium
payment received in return for the sale of the call offsets the premium payment made to
purchase the put.

Futures contracts, basis contracts, puts and calls on futures contracts
are the most commonly used derivative products. The customer seeking the most common
product, a fixed price, can almost be satisfied by the marketer utilizing these
tools.

However, the NYMEX only offers futures contracts for electricity used
during peak periods. Until it begins offering futures contracts covering off-peak
usage, marketers must use yet another financial toolthe electric rate swap.

Electric Rate Swaps. NYMEX has chosen to implement futures
contracts only for on-peak periodsthose 736 business hours each month, or 4416 hours
in a year during which prices are the most volatile. But this is only about half
the hours in a year, and customers want power 24 hours a day, 365 days each year.

Customers require that the marketer deliver power during the off-peak
periods, and to similarly guarantee a price to the customer for those off-peak hours.

Off-peak power is by definition less expensive than on-peak power, and
it generally has less price volatility. However, the price risk associated with off-peak
power is still significant. In some regions, it is not unusual for market indices to list
ranges of over $5/mWh for off-peak power. This is far greater than the typical profit
margin on those sales. Therefore the prudent marketer must hedge the risks associated with
those price swings.

This is accomplished by means of what is called an "electric rate
swap," and specifically, a "plain vanilla swap."

In a plain vanilla swap, the marketer exchanges a fluctuating rate,
typically a market rate, for a fixed rate. Contracts calling for market rates often cite a
commonly-accepted electricity market index, such as the Dow Jones Telerate indices
or McGraw-Hills Power Markets Week indices. They are also traded at common delivery
points, such as at the "citygate1" of utilities with large numbers of customers
which might be available for marketers to serve.

In order to complete the construction of the customers price, the
marketer must obtain a "swap" to lock in the price of off-peak power to the
customer, typically at the citygate of the utility serving the customer.

A swap which is not done to the citygate might require the marketer to
get yet another basis contract for off-peak power, or to simply estimate and absorb the
risk associated with swings in transmission prices during off-peak periods. For our
purposes, we are assuming a swap to the citygate.

Swaps are available from swap market makers. These may be power
marketers, or even financial institutions. As will be described below, swaps are the
purest of financial transactions, with no possibility of physical electric delivery.

When added to the other products used to produce a price for
electricity to the customer, the final calculation looks like this:The marketer
now has a cost of purchasing commodity to supply its customer$17.83/mWh. To this it
adds a figure to cover its overhead, including residual price risks, and acounts
receivable risks, an additional figure to cover its profit, and without further ado, it
can make a price offer.

Understanding Swaps

Electricity price swaps, while playing only a minor role in our story
thus far, are the most flexible of financial tools, and may be used to create a variety of
innovatively priced products.

Swaps are traditionally described using a device known as a "swap
diagram." To understand the swap diagram, it is important to remember that what we
are describing is the flow of money, and not the flow of electricity. Diagram 1 is
a description of our simple plain vanilla swap, of the type used to complete our simple
fixed price transaction.

Customer 1 (C1)

+2.5¢/kWh fluctuating

-2.5¢/kWh fluctuating

+3.0¢/kWh fixed

+3.0¢/kWh Fixed

(Original Rate)

(Paid by C2 to C1)

(Paid by C1 to C2)

(Final Rate)

Customer 2 (C2)

+4.5¢/kWh fixed

-3.0¢/kWh fixed

+1.5¢/kWh Fixed

+1.5¢/kWh fixed

+2.5¢/kWh fluctuating

+4.0¢/kWh Fixed

(Original Rate)

(Paid by C1 to C2)

(Subtotal)

(Subtotal)

(Paid by C2 to C1)

(Final Rate, in which 1.5¢ is fixed, 2.5¢ fluctuates)

In the diagram and accompanying table, Customer 1 (C1)
starts out paying Marketer 1 a "fluctuating rate," which averages
2.5¢/kWh. Customer 1s problem is that it needs to set a budget, and protect itself
against market fluctuations.

To do this, it needs to identify a counterparty which is willing
to take the market risk, in return for a fixed payment stream. The fixed payment stream is
generally higher than the projected payment stream, based upon historical usage, to
take into account the risk C2 is taking on. C2 is willing to take the risk, because it
expects to come out ahead in the end (although there is no guarantee that it will). CI, on
the other hand, doesnt expect to come out aheadit is merely buying insurance
against extreme price fluctuations.

Because this is a pure financial transaction, Marketer 1 need not even
be aware it is taking place. C2 simply pays C1 an amount equal to its electric bill. In
return, C1 pays C2 three cents per kWh. The ultimate result is that the 2.5¢ (average)
payment to Marketer 1 is cancelled out by C2s payment, leaving C1 with a 3¢/kWh
fixed payment to C2. C1 has accomplished its goal of rate stabilization.

C2 has the goal of getting an immediate rate reduction, with the
possibility of future rate reductions should the cost of generating power fall. It
accomplishes this by enticing C1 to pay it a premium rate in return for rate
certaintyC1 pays 3¢, reducing C2s fixed costs to only 1.5¢/kWh.

Of course, C2 has to pay C1s variable-rate electric bill, but
that is only 2.5¢ currently. Add the 1.5¢ fixed payment and the 2.5¢ variable payment
and C2 is still only subject to a current charge of 4¢/kWh. C2 has an immediate savings
of .5¢/kWh, and the possibility of additional savings should the cost of power from
Marketer 1 fall in the future.

In order to accomplish this transaction, the counterparties need to be
comfortable with each others financial situation. If one party goes bankrupt during
the term of a swap, the other wont get the benefit of its bargain. This is what is
known as counterparty risk.

In addition, it is extremely difficult to find counterparties with
precisely counter-vailing risk profiles. For example, it is unlikely that both C1 and C2
use precisely the same amount of electricity. This means there will be unhedged leftovers,
or nubs on the transaction.

The development of price indices creates the conditions for solving
most of these problems. By standardizing the fluctuating measure, price indices have
permitted there to be created a market in price swaps. Rather than identifying a
counterparty for each transaction, familiarizing each with the credit risks of the other,
and dealing with transaction nubs, customers can deal with market-makers. Market
makers establish prices for swapping the index, and handle many transactions, quickly and
cheaply.

Today, it is rare for counterparties to deal with each other directly.
It is far more efficient to work through the market makers. The market for swaps is
therefore coming to look more like this:

Freedom to Focus on Core Competencies

Rather than the one-on-one transactions we have had to do in the past
several years, market-makers make it possible to do many transactions without perfect
matches among customers. This vast increase in liquidity is permitting new rate products
to be created which allow companies to focus on their core competencies, such as running
powerplants well.

Example 1: Coal priced to electricity

For example, many utilities are moving away from long-term fixed price
coal supply contracts. These contracts have often resulted in power costs which are
"out-of-the-market," even though the powerplant is running well.

An ideal solution to this problem is a coal supply contract which is
price-indexed to electricity. That way, if electric prices fall, coal prices fall. If
electric prices rise, coal prices rise. In either case, so long as the plant is run well,
the power company will continue to make a profit.

Without electric price indices, it is very difficult (and expensive)
for a coal company to offer coal at prices marked to electricity. One has to establish
what the measure is and gain confidence that it cant be manipulated. With an
electric price index in place, it is a relatively simple matter to offer coal at
electricity-based prices. The transaction looks like this (arrows show direction of
money):

The Utility pays the Coal Supplier a rate which fluctuates with an
electric price index. The Coal Supplier, needing a fixed payment stream to cover its
largely fixed mining costs, "swaps" that "fluctuating" payment stream
for a "fixed" payment stream through a price swap market-maker. The market-
maker is continually swapping fixed for fluctuating based upon the index, and so can
readily name a price for doing the swap.

Example 2: Selling electricity at market rates without risk

Increasingly, electric power customers are seeking electric suppliers
which are willing to sell at the "market price." Indices provide not only the
basis for determining that market price, but a means of hedging the risk associated with
such an offer. The customer wants market-based rates. The power company needs to cover the
fixed costs associated with power production. These wants and needs can be reconciled
through the use of price indices:

In this case the Utility receives a "fluctuating" payment
stream from the customer, based upon the "market price" of electricity. But
because that market price is based on an index, it can be easily "swapped" for a
fixed rate with a market-maker.

Electric rate swaps can also be used to create "exotic"
specialized electric rates, such as electric rates which fluctuate with aluminum prices,
steel prices or natural gas prices. These are useful for customers which see their
profits, and their ability to pay for electricity, closely linked to the price of another
commodity. These cross commodity swaps can be extremely attractive to large
specialized industrial customers.

POWER MARKETING: THE KEY CUSTOMER SERVICE FOR A COMPETITIVE MARKET

The purpose of this treatise is to explain the fundamental principals
and products used in power marketing. As in other commodity industries, customers will
select their electric power suppliers based primarily upon price. Power marketing creates
prices to offer to potential customers.

Prices make things simple for the customer, yet creating them makes
business much more complicated for suppliers. Customers generally dont want to hear
about the difficulties of a supplier in arranging for futures contracts in a timely
fashion, or about the illiquidity of basis trading for one of their locations. From the
customers perspective, weather-related variations in usage should not result in
price changesthat is a problem for the supplier, not for the customera
marketing problem to be managed with marketing tools.

The natural gas industry, the closest analog to the power industry,
delivers $60 billion worth of gas to retail customers every year. It is supported by $300
billion in gas futures trading and another $300 billion in over-the-counter derivative
products. That is, the wholesale market is ten times the size of the retail market.
Virtually this entire market was created in the 1990s.

Presuming that electricity follows a similar course, in a few years the
larger, $200 billion retail electricity market will be served by a two trillion dol1lar
derivatives market, consisting half of electricity futures contract trades and half of
options, swaps, forwards and basis trades.

From this it should be clear why there are now over 250 nonutility
power marketers registered to do business in the U.S. There is a great deal of work to be
donework which has little or nothing to do with the traditional functions of the
electric power industry.

The addition of power marketing to the power industry does not take
anything away from existing power companiesthis is not a zero sum game. Generation,
transmission and distribution will continue. Power marketing is an entirely new function.
It can be performed by traditional power companies, or by others, but it must be
performed. Customers demand it.

About The Author:

Mr. Spiewak is Secretary of the Power Marketing Association, and General Counsel for
Metromedia Energy, Inc., an electric and natural gas broker and retailer.